Water-based drilling fluids using latex additives

ABSTRACT

A water-based drilling fluid having a polymer latex capable of providing a deformable latex film on at least a portion of a subterranean formation has been discovered to provide reduced drilling fluid pressure invasion when used to drill in shale formations for hydrocarbon recovery operations. A precipitating agent such as a silicate or an aluminum complex (e.g. sodium aluminate) is preferably used in conjunction with the polymer. Typically, the water present contains a salt to form a brine, often to saturation, although the invention may be practiced with fresh water. If a salt is employed, it is often helpful to additionally employ a surfactant, such as a betaine, for example.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation in part of U.S. patent applicationSer. No. 09/785,842 filed on Feb. 16, 2001 that issued Mar. 9, 2004 asU.S. Pat. No. 6,703,351 B2, and claims the benefit of U.S. ProvisionalApplication Ser. No. 60/211,162 filed Jun. 13, 2000.

FIELD OF THE INVENTION

The present invention relates to water-based drilling fluids used duringpetroleum recovery operations, and more particularly relates, in oneembodiment, to using water-based drilling fluids containing additives toinhibit penetration of the borehole wall by the fluid.

BACKGROUND OF THE INVENTION

Drilling fluids used in the drilling of subterranean oil and gas wellsas well as other drilling fluid applications and drilling procedures areknown. In rotary drilling there are a variety of functions andcharacteristics that are expected of drilling fluids, also known asdrilling muds, or simply “muds”. The drilling fluid is expected to carrycuttings up from beneath the bit, transport them up the annulus, andallow their separation at the surface while at the same time the rotarybit is cooled and cleaned. A drilling mud is also intended to reducefriction between the drill string and the sides of the hole whilemaintaining the stability of uncased sections of the borehole. Thedrilling fluid is formulated to prevent unwanted influxes of formationfluids from permeable rocks penetrated and also often to form a thin,low permeability filter cake which temporarily seals pores, otheropenings and formations penetrated by the bit. The drilling fluid mayalso be used to collect and interpret information available from drillcuttings, cores and electrical logs. It will be appreciated that withinthe scope of the claimed invention herein, the term “drilling fluid”also encompasses “drill-in fluids”.

Drilling fluids are typically classified according to their basematerial. In water-based muds, solid particles are suspended in water orbrine. Oil can be emulsified in the water or brine. Nonetheless, thewater is the continuous phase. Oil-based muds are the opposite. Solidparticles are suspended in oil and water or brine is emulsified in theoil and therefore the oil is the continuous phase. Oil-based muds thatare water-in-oil emulsions are also called invert emulsions. Brine-baseddrilling fluids, of course are a water-based mud in which the aqueouscomponent is brine.

Optimizing high performance water base mud design is commonly at theforefront of many drilling fluid service and oil operating companies'needs due to the various limitations of invert emulsion fluids. Invertemulsion fluids formulated with traditional diesel, mineral or the newersynthetic oils are the highest performing drilling fluids with regard toshale inhibition, borehole stability, and lubricity. Various limitationsof these fluids, however, such as environmental concerns, economics,lost circulation tendencies, kick detection, and geologic evaluationconcerns maintains a strong market for high performance water basedfluids. Increased environmental concerns and liabilities continue tocreate an industry need for water based drilling fluids to supplement orreplace the performance leading invert emulsion mud performance.

A particular problem when drilling into shale formations withwater-based fluids is the pore pressure increase and swelling frompenetration of the shale by the fluid. Shale stabilizers are typicallyadded to the mud to inhibit these phenomena and to stabilize the shalefrom being affected by the mud.

Reducing drilling fluid pressure invasion into the wall of a borehole isone of the most important factors in maintaining wellbore stability. Itis recognized that sufficient borehole pressure will stabilize shales tomaintain the integrity of the borehole. When mud or liquid invades theshale, the pressure in the pores rises and the pressure differentialbetween the mud column and the shale falls. With the drop indifferential pressure, the shale is no longer supported and can easilybreak off and fall into the well bore. Likewise, the invasion of waterinto the shale matrix increases hydration or wetting of the partiallydehydrated shale body causing it to soften and to lose its structuralstrength. Chemical reactivity can also lead to instability. There isalways a need for a better composition and method to stabilize the shaleformations.

In the drilling of depleted sands, there is also a need to prevent ofintrusion of drilling fluid through the borehole and into the formation.Rather than concern for formation stability, the loss of drilling fluidand resulting higher production costs are the more commonly the mainconcern. It would be desirable to be able to reduce the loss of drillingfluid into depleted sands.

It is apparent to those selecting or using a drilling fluid for oiland/or gas exploration that an essential component of a selected fluidis that it be properly balanced to achieve all of the necessarycharacteristics for the specific end application. Because the drillingfluids are called upon to do a number of tasks simultaneously, thisdesirable balance is difficult to achieve.

It would be desirable if compositions and methods could be devised toaid and improve the ability of drilling fluids to simultaneouslyaccomplish these tasks.

SUMMARY OF THE INVENTION

Accordingly, it is an object of the present invention to provide methodsto stabilize shale formations and avoid loss of fluids into depletedsands formations when drilling with water-based drilling fluids.

It is another object of the present invention to provide water-baseddrilling fluids that reduce the rate of drilling fluid pressure invasioninto the borehole wall.

Still another object of the invention is to provide a composition andmethod that increase the pressure blockage, reliability, magnitude, andpore size that can be blocked with water-based fluids for stabilizingshale formations.

In carrying out these and other objects of the invention; there isprovided, in one form, a water-based drilling fluid including water anda polymer latex capable of providing a deformable latex film or seal onat least a portion of a subterranean formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a chart of the formation pressure as a function of time fora pressure invasion test using various intermediate test formulations;

FIG. 2 is a graph of the surfactant effect on GENCAL 7463 particle sizein 20% NaCl/1 lb/bbl (2.86 g/l) NEWDRILL PLUS/1 lb/bbl (2.86 g/l)XAN-PLEX D/0.5 lb/bbl (1.43 g/l) sodium gluconate/3 lb/bbl (8.58 g/l)NaAlO2/5% by volume GENCAL 7463;

FIG. 3 is a graph of the influence of polymer resins (3 lb/bbl, 8.58g/l) on GENCAL 7463 particle size distributions after 16 hours, 150° F.(66° C.) hot roll in 20% NaCl/0.75 lb/bbl (2.15 g/l) XAN-PLEX D/0.5lb/bbl (1.43 g/l) sodium D-gluconate/0.4 lb/bbl (1.14 g/l) NEW-DRILLPLUS/2 lb/bbl (5.72 g/l) BIO-PAQ/3 lb/bbl (8.58 g/l) NaAlO₂/3% GENCAL7463/1 lb/bbl (2.86 g/l) EXP-152;

FIG. 4 is a graphical comparison of the effects on mud properties forEXP-154 versus ALPLEX in 12 lb/gal (1.44 kg/l) mud; the base mud was 20%NaCl/0.5 lb/bbl (1.43 g/l) XAN-PLEX D/2 lb/bbl (5.72 g/l) BIO-LOSE/1lb/bbl (2.86 g/l) NEW-DRILL PLUS/3% EXP-155/150 lb/bbl (429 g/l)MIL-BAR/27 lb/bbl (77.2 g/l) Rev Dust;

FIG. 5 is a graph of PPT test results for ALPLEX, EXP-154/EXP-155, andISO-TEQ fluids;

FIG. 6 is a graph showing the effect of circulation on EXP-154/EXP-155mud performance;

FIG. 7 is a graph showing the effect of latex on mud properties in 9.6lb/gal (1.15 kg/l) 20% NaCl fluid after 16 hours, 250° F. (121° C.) hotroll; the base fluid was 20% NaCl/1 lb/bbl (2.86 g/l) XAN-PLEX D/0.4lb/bbl (1.14 g/l) NEW-DRILL PLUS/2 lb/bbl (5.72 g/l) BIO-PAQ/5 lb/bbl(14.3 g/l) EXP-154/10 lb/bbl (28.6 g/l) MIL-CARB/27 lb/bbl (77.2 g/l)Rev Dust;

FIG. 8 is a graph showing the effect of latex on mud properties in 12lb/gal (1.44 kg/l) after hot rolling for 16 hours at 250° F. (121° C.);the base fluid was 20% NaCl/0.75 lb/bbl (2.15 g/l) XAN-PLEX D/0.4 lb/bbl(1.14 g/l) NEW-DRILL PLUS/3 lb/bbl (8.58 g/l) BIO-PAQ/5 lb/bbl (14.3g/l) EXP-154/150 lb/bbl (429 g/l) MIL-CARB/27 lb/bbl (77.2 g/l) RevDust;

FIG. 9 is a graph of 96 hour Mysidopsis bahia range-finder results forexperimental products in 12 lb/gal (1.44 kg/l) fluids where the basefluid is 20% NaCl/0.5 lb/bbl (1.43 g/l) XAN-PLEX D/0.4-1 lb/bbl(1.14-2.86 g/l) NEW-DRILL PLUS/2 lb/bbl (5.72 g/l) MIL-PAC LV (orBIO-PAQ)/150 lb/bbl (429 g/l) MIL-BAR;

FIG. 10 is a graph of high temperature high pressure (HTHP) fluid lossrate on 50 mD cement disk for the mud containing 3% latex polymer afterbeing hot rolled at 250° F. for 16 hours; and

FIG. 11 is a photograph of an internal filter cake formed using themethod of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

It has been discovered that a polymer latex added to a water-baseddrilling fluid can reduce the rate the drilling fluid pressure invadesthe borehole wall of a subterranean formation during drilling. Thepolymer latex preferably is capable of providing a deformable latex filmor seal on at least a portion of a subterranean formation. Within thecontext of this invention, the terms “film” or “seal” are not intendedto mean a completely impermeable layer. The seal is considered to besemi-permeable, but nevertheless at least partially blocking of fluidtransmission sufficient to result in a great improvement in osmoticefficiency. In a specific, non-limiting embodiment, a submicron polymerlatex added to a high salt water-based mud containing an optional, butpreferred combining/precipitating agent, such as an aluminum complexwill substantially reduce the rate of mud pressure penetration intoshale formations. The pressure blockage, reliability, magnitude and poresize that can be blocked are all increased by the latex addition.Inhibiting drilling fluid pressure invasion into the wall of a boreholeis one of the most important factors in maintaining wellbore stability.

The essential components of the water-based drilling fluids of thisinvention are the polymer latex and water, which makes up the bulk ofthe fluid. Of course, a number of other common drilling fluid additivesmay be employed as well to help balance the properties and tasks of thefluid.

The polymer latex is preferably, but not limited to a carboxylatedstyrene/butadiene copolymer or a sulfonated styrene/butadiene copolymer.A particular, non-limiting carboxylated styrene/butadiene copolymer isGENCAL 7463 available from Omnova Solution Inc. A particular,non-limiting sulfonated styrene/butadiene copolymer is GENCEAL 8100 alsoavailable from Omnova Solution Inc. Other suitable polymer latexesinclude, but are not limited to polymethyl methacrylate, polyethylene,polyvinylacetate copolymer, polyvinyl acetate/vinyl chloride/ethylenecopolymer, polyvinyl acetate/ethylene copolymer, natural latex,polyisoprene, polydimethylsiloxane, and mixtures thereof. A somewhatless preferred polymer latex is polyvinylacetate copolymer latex, morespecifically, an ethylenevinyl chloride vinylacetate copolymer. Whilepolyvinylacetate copolymer latices will perform within the methods ofthis invention, they generally do not perform as well as thecarboxylated styrene/butadiene copolymers. The average particle size ofthe polymer latex is preferably less than 1 micron or submicron and mostpreferably having a diameter of about 0.2 microns or 0.2 microns orless. Other polymers in the disperse phase may be found to work. It isanticipated that more than one type of polymer latex may be usedsimultaneously. The proportion of the polymer latex in the drilling mud,based on the total amount of the fluid may range from about 0.1 to about10 vol. %, preferably from about 1 to about 8 vol. %, and mostpreferably from about 2 to about 5 vol. %.

The sulfonated latexes of the present invention have an added advantagein that they can often be used in the absence of a surfactant. This cansimplify the formulation and transportation of the drilling fluidadditives to production sites. This can also reduce costs in someapplications. In applications of drilling in depleted sands, there isoften no need of a precipitating agent. In the depleted sandsapplications, there is also often no need of a surfactant forcarboxylated styrene/butadiene copolymers for fresh water applications.

The optional salt may be any common salt used in brine-based drillingfluids, including, but not necessarily limited to calcium chloride,sodium chloride, potassium chloride, magnesium chloride, calciumbromide, sodium bromide, potassium bromide, calcium nitrate, sodiumformate, potassium formate, cesium formate and mixtures thereof. By a“high salt content” is meant at least 20 weight percent, and saturatedbrine solutions are preferred in one non-limiting embodiment. It willappreciated that it is impossible to predict in advance what the saltcontent of a particular saturated brine solution will be since thesaturation point depends on a number of factors including, but notlimited to the kinds and proportions of the various components of thewater-based fluid. The salt is optional because the invention willperform without it, that is, using fresh water.

Another optional component is precipitating agent. Suitableprecipitating agents include, but are not limited to, silicates,aluminum complexes, and mixtures thereof. Suitable aluminum complexesinclude, but are not limited to, sodium aluminate, NaAl₂O₂, sometimeswritten as Na₂OAl₂O₃, aluminum hydroxide, aluminum sulfate, aluminumacetate, aluminum nitrate, potassium aluminate, and the like, andmixtures thereof (especially at pH of >9 for these compounds to besoluble in water). The proportion of the precipitating agent in thedrilling mud, based on the total amount of the fluid may range fromabout 0.25 to about 20 lb/bbl (about 0.71 to about 57.2 g/l), preferablyfrom about 1 to about 10 lb/bbl (about 2.86 to about 28.6 g/l) and mostpreferably from about 2 to about 7 lb/bbl (about 5.72 to about 20 g/l).Without being limited to a particular theory, the precipitating agent isbelieved to chemically bound to the surface of the clay of the boreholeand provide a highly active polar surface.

Another optional component of the composition of the invention is asurfactant. If the surfactant is present, the surfactant treated latexwets the surface strongly and accumulates to form a film or coating thatseals fractures and defects in the shale. Suitable wetting surfactantsinclude, but are not limited to, betaines, alkali metal alkyleneacetates, sultaines, ether carboxylates, and mixtures thereof. It hasbeen determined that surfactants are particularly beneficial when saltsare present in the drilling fluid, and are not as preferred in freshwater fluid systems.

The proportions of these components based on the total water-baseddrilling fluid are from about 0.1 to 10 volume % of polymer latex, atleast 1 wt % of salt (if present), from about 0.25 to 20 lb/bbl (about0.71 to about 57.2 g/l) of precipitating agent (if present), from about0.005 to about 2 vol. % of surfactant (if present), the balance beingwater. In a more preferred embodiment, the proportions range from about1 to 8 vol. % of polymer latex, at least 1 wt % of salt (if present),from about 1 to 10 lb/bbl (about 2.86 to about 28.6 g/l) ofprecipitating agent (if present) from about 0.01 to about 1.75 vol. % ofwetting surfactant (if present), the balance being water.

It is desired that the sodium aluminate or other precipitating agent bein a metastable form in the mud, which means that it is in suspension orsolution, but precipitates out upon the borehole wall. Typically,aluminum compounds have been added to the mud on site. If added to mudformulations earlier, they tend to be unstable and precipitateprematurely.

Since the development of pore pressure transmission (PPT) testing, theeffects of various chemical additives on pore pressure transmissionrates have been evaluated. Testing has focused primarily on theperformance of salts, glycols, and precipitating agents such assilicates and aluminum complexes. Improvements in PPT test equipment andmethods have accompanied the general interest and search for increasingmore efficient water-based mud systems that approach the PPT testperformance of invert emulsion fluids. While other investigators havefound silicate fluids to be especially effective for reduced poorpressure transmission rates, silicate fluids have not been widely useddue to limitations of these fluids. Although lower pore pressuretransmission rates have been demonstrated for salts, glycols, andaluminum complexing agents, these products still do not approach theperformance of invert emulsion fluids.

A combination of a new formulation approach as well as modification tothe PPT test procedure was used to demonstrate the efficacy of analternative approach to enhance the performance of water-based mudsystems. Water-dispersible polymers were selected to provide sources ofsmall, deformable particles to provide a sealing and blocking effect onthe shale. The first of these polymers was tested on the PPT test in afluid with other products.

The invention will be further illustrated with respect to the followingexamples, which are only meant to further illuminate the invention, andnot limit it in any way.

EXAMPLE1 Fluid Intermediate Preparation

The following Example is the first preparation of the intermediatecompositions of this invention. Unless otherwise noted, the latex in theExamples is 728 Latex, a polyvinylacetate latex.

Grams per barrel Grams per 7 barrels Component (per 159 l) (per 1,113 l)Tap water 310 2170 Sodium aluminate 2  14 LIGCO 2  14 AIRFLEX 728 10.5 73.5 (75 cc) The mixture was hot rolled. After 6 days, the pH was11.51. The bottom of the jar was about 75% covered with 1/32″ (0.79 mm)fines. The following components were then added, again given in gramproportions for a single barrel and 7 barrels, respectively: NEWDRILLPLUS 0.4   2.8 NaCl (20%) 77.5  540 MILPAC LV 2  14 The fluid with thelatex and the NEWDRILL+ had a light brown color. LD8 was added tocontrol foaming. The resulting mixture was hot rolled for four hours at150° F. (66° C.). The final pH was 10.75.

EXAMPLE 2 Shale Pressure Penetration Determination

The pore pressure transmission (PPT) device is based on a 1500 psi(10,300 kPa) Hassler cell designed for 2.5 cm diameter core plugs from2.5 cm to 7.5 cm in length. A Hassler cell is a cylinder with a pistoninserted in each end. The core is held between the two pistons. A rubbersleeve is placed around the core and the pistons to seal around the coreand prevent flow around the core. The outside of the sleeve is pressuredto make a good seal. These tests use a core 25 mm in diameter and 25 mmlong.

The low pressure side of the core (formation side) is fitted with a 1liter, 2000 psi. (13,800 kPa), stainless steel accumulator to provideback pressure. The high pressure side of the core is connected to twosimilar accumulators, one for pore fluid, and one for the test fluid.The pressure in each accumulator is controlled with a manual regulatorfed by a 2200 psi (15,200 kPa) nitrogen bottle.

All pressures are monitored with Heise transducers. The transducerpressures are automatically computer logged at preset intervals.

The cell is enclosed in an insulated chamber and the temperaturemaintained with a 200 watt heater. The heater is controlled with a Dwyertemperature controller driving a Control Concepts phase angle SCRcontrol unit. Temperature control is accurate to +/−0.05° C.

A pressure is applied to one end of the core and the flow through thecore is measured. The piston on the low pressure side is filled withliquid, and blocked, so an increase in liquid pressure is measuredrather than flow. A very small amount of liquid flow through the corewill make a large rise in the pressure, making the cell sensitive enoughto measure flow through shale. Shale has a very low permeability, so theflow of fluid through it is very small. Pressure is plotted versus time.Results are expressed as formation pressure (FP). If the FP increasesovertime, there is pressure penetration; if the formation pressuredecreases over time there is not, and the latter is what is desired. Thefluid of Example 1 was used. Three 50% displacements of 50 cc each wereperformed during and just after heating up of the test cell. One run wasstarted at 100% displacement and the temperature was difficult tocontrol, so it was decided starting at 50% was better.

-   -   Temperature=155° F. (68.3° C.)    -   Borehole side pressure=250 psi (1,720 kPa)    -   Confining pressure=370 psi (2,550 kPa)

Formation Pressure Time, hours:minutes psi kPa 0   48.1 332 1:30 47.9330 2:00 47.6 328 7:15 50.9 359

Eventually, 50 cc of fluid was displaced up to 50% within 2° F. (1.1°C.) temperature variation. The pressure rose to 52.7 psi (363 kPa).Formation heat was turned off, and the temperature was 147° F. (64° C.).Displacement pulled the formation pressure down to 36 psi (248 kPa),then rose to 80.2 (553 kPa) over the next two days. The initialformation pressure decrease demonstrated that the formulation of theinvention inhibited pressure penetration.

EXAMPLE 3 Fluid Intermediate Preparation—Proportions in Grams UnlessOtherwise Noted

Component Per barrel (per 159 l) Per 7 barrels (per 1,113 l) Tap water310 2170 cc Sodium aluminate 2  14 LIGCO 2  14 AIRFLEX 728 10.5  75 ccLatex NEWDRILL PLUS 0.4   2.8 NaCl (20%) 77.5  540 MILPAC LV 2  14

The sodium aluminate and AIRFLEX728 latex were mixed together andallowed to stand over the weekend. The mixture was then hot rolled at150° F. (66° C.) for two hours. The salt and polymers were then added.The sequence of addition to the sodium aluminate/latex mixture was: PHPA(partially hydrolyzed polyacrylamide; NEWDRILL PLUS), followed bymixing; then half of the salt, followed by MILPAC LV, followed by theother half of the salt. The mixture was hot rolled overnight.

EXAMPLE 4 Shale Pressure Penetration Determination

-   -   Borehole side pressure=250 psi (1,720 kPa)    -   Confining pressure=370 psi (2,550 kPa)

Formation Pressure Time, hours:minutes psi kPa 0   46.3 319  5:49 2.3 16 7:36 0.6* 41 50:00 65.0 448 *The confining pressure was raised to 410psi (2,830 kPa) and the borehole pressure was raised to 300 psi (2,070kPa) at this point.

EXAMPLES 5 and 6, COMPARATIVE EXAMPLES A-F

Two other inventive formulations (Examples 5 and 6) and six comparativeExamples (A-F) were prepared and tested. The results are shown inFIG. 1. As indicated the Inventive Examples 5 and 6 both gave thedesired results of decreasing formation pressure over time. Thecomparative Examples undesirably gave increasing formation pressuresover time. The composition identities are given on FIG. 1 itself. Thedesignation “CORE: P2 PARALLEL” refers to the core being Pierre Shale inparallel orientation.

These results verify the necessity of having all three components: thesalt, the latex, and the sodium aluminate (Examples 5 and 6). Use of thelatex alone (comparative Ex. A), use of salt only (comparative Ex. B),use of the latex together with salt only (comparative Example C), use ofsodium aluminate and the salt only (comparative Ex. D), use of thesodium aluminate and salt only (comparative Ex. E), and use of thesodium aluminate with salt only (comparative Ex. F) were all found to beineffective, or at least certainly not as effective as the inventivecomposition.

Further experimental evidence indicates that some latex products exhibita synergistic effect with aluminum complexes that results in improvedpore pressure transmission characteristics. Stable drilling fluidsystems have been formulated with latex that remain dispersed andflexible in highly saline (high salt content) fluids. Inventive drillingfluids provide pore pressure transmission performance closer tooil-based fluids than what is exhibited by current aluminum-baseddrilling fluids. Two features of this system are believed to be the maincontributors to shale stabilization. First, the ultra-fine, deformablelatex particles (having a preferable diameter of about 0.2 microns)mechanically seal shale micro-fractures and physically prevent furtherintrusion of drilling fluids into sensitive shale zones. Secondly, latexco-precipitation with precipitating agents, if present, such as aluminumcomplexes, produces a semi-permeable membrane on shale surfaces thatchemically improves the osmotic efficiency between the fluid and theborehole.

Three experimental additives were discovered for the inventive fluids:EXP-153, EXP-154 and EXP-155. EXP-153 is a sulfonated polymer resin usedto control HTHP fluid loss in this system. EXP-154 is considered analternative to aluminum complex product ALPLEX. Compared to ALPLEX,EXP-154 exhibits much better compatibility with latex fluids. EXP-155 isa modified latex product. Compared to other commercially availablelatices EXP-155 displays less sensitivity to electrolytes and does notflocculate in 20% sodium chloride fluids at temperatures up to 300° F.(149° C.). Furthermore, due to the wide temperature range between itsglass transition temperature (T_(g)) and melting point (T_(m)), theparticles of EXP-155 remain deformable and capable of plugging shalemicro-fractures at most application temperatures. The toxicities of allof these products meet the requirement for fluid disposal in the Gulf ofMexico.

Formulations and Fluid Properties

All fluids were mixed according to established Baker Hughes INTEQ mixingprocedures. The initial and final Bingham Plastic rheological propertiesof plastic viscosity, yield point, ten second gels, and ten minute gelswere measured by Fann 35 viscometer at 120° F. (49° C.). The initial andfinal pH and API filtrate were recorded. HTHP fluid loss at 250° F.(121° C.) was measured after static and dynamic aging for 16 hours at250° F. (121° C.).

Latex Stability

The stability of the latex samples were first evaluated in 20% and 26%NaCl solutions by the following procedure:

-   1. Add 332 ml 20% (or 26%) NaCl water solution into a mixer cup and    start mixing.-   2. Slowly add 18 ml tested latex sample into the solution and adjust    the Prince Castle mixer to 4000 rpm with Variac and tachometer.-   3. After stirring 5 minutes, slowly add 3 grams NaAlO₂ into the    above solution and mix for a total of 20 minutes. During the mixing    period it may be necessary to add about 5 drops defoamer (LD-8) if    foaming is observed.-   4. Put this fluid into a jar and statically age for 16 hours at    150° F. (66° C.).-   5. Remove the jar from the oven and cool to room temperature.    Observe the fluid for flocculation and separation.-   6. If there is no separation or flocculation, sieve the fluid with a    100-mesh (0.150 mm) screen. Observe sieve for amount of retained    latex particles.

Additional evaluations were performed only for those samples havingpassed the above screening test. A Malvern Mastersizer Particle SizeAnalyzer was used to measure the particles size distributions of latexin formulated fluids. The small sample dispersion unit and the standardrefractive index 50HD (Particle R.I.=1.5295, 0.1000 and DispersantR.I.=1.3300) were used in all of the particle size distribution tests.20% NaCl water solution with pH adjusted to 11.5.

Shale Inhibition Test

The shale inhibition characteristics were determined by shale dispersiontests that included static wafer test, and pore pressure (PPT) tests. Inthe PPT test, a preserved Pierre II shale core, 1 inch diameter by 0.9inch long (2.54 cm×2.29 cm long), is placed between two pistons, asdescribed previously in Example 2. The circumference of the shale andpistons are sealed with a rubber sleeve. The plug is oriented with thebedding planes in the parallel or high permeability direction. Drillingfluid at 300 psi (2,070 kPa) is displaced through the upstream piston(borehole side) and seawater at 50 psi (345 kPa) is displaced throughthe downstream piston (formation side). The seawater in the downstreampiston is contained with a valve. As mud filtrate enters the boreholeend of the plug, connate water in the shale is displaced into theformation piston.

Latex Stability

As noted above, initial experiments indicated that some latex products(emulsion polymers) produced synergistic effects with an aluminumcomplex, resulting in improved pore pressure transmissioncharacteristics of the fluids. This result revealed a new approach tothe design of highly inhibitive, water-based fluids. However, latex isgenerally considered to be a metastable system. The large surface of theparticles is thermodynamically unstable and any perturbation affectingthe balancing forces stabilizing the polymer dispersion results in achange in the kinetics of particle agglomeration. Most commerciallattices, which are designed for the production of synthetic rubber orthe application of painting/coating, are sensitive to increasingelectrolytic concentration and temperature.

As shown in Table I, among 16 latex samples tested in 26% and 20% NaClsolutions, none of them is stable in 26% NaCl and only AIRFLEX728 andGENCAL7463 are relatively stable in 20% NaCl. Clearly, for successfulapplications of latex in drilling fluids, latex stability in high saltenvironments and at elevated temperatures must be improved. A commontechnique used to increase latex stability in electrolyte solutions isthe addition of some surfactants. FIG. 2 compares the effect of EXP-152on the particle size distributions of AIRFLEX728 with that ofGENCAL7463. These results indicate that a blend of GENCAL 7463 andEXP-152 may be a stable product for drilling fluid applications.

TABLE I Stability Test for Latex Products in NaCl Solution StabilityAfter 16 Hours Static Aging Tg 26% NaCl/3 lb/bbl 20% NaCl/3 lb/bbl Ex.Latex Samples (° C.) (8.58 g/l) NaAlO₂ (8.58 g/l) NaAlO₂ VinylAcetate/Ethylene Vinyl Chloride 7 AIRFLEX 728  0 Flocculation but pass100 mesh Flocculation/Coagulation Vinyl Acetate/Ethylene 8 AIRFLEX 426 0 Flocculation/Coagulation Flocculation/Coagulation 9 AIRFLEX 7200  0Flocculation/Coagulation Flocculation/Coagulation 10 VINAC XX-211 N/AFlocculation/Coagulation Flocculation/Coagulation 11 ELVACE 40722-00 N/AFlocculation/Coagulation Flocculation/Coagulation CarboxylatedStyrene/Butadiene 12 GENCAL 7463  13 Flocculation but pass 100 meshFloc. at 150° F. (66° C.) but stable at 75° F. (24° C.) 13 GENCAL 7470N/A Flocculation/Coagulation — 14 GENFLO 576 N/AFlocculation/Coagulation — 15 TYLAC 68219 N/A Flocculation but pass 100mesh Flocculation but pass 100 mesh 16 TYLAC CPS 812 N/AFlocculation/Coagulation — 17 TYCHEM 68710 N/A Flocculation/Coagulation— 18 ROVENE 9410 −56 Coagulation Coagulation 19 ROVENE 6140 −27Coagulation Coagulation Carboxylated Acrylic Copolymer 20 SYNTHEMUL CPSN/A Flocculation/Coagulation — 401 21 SYNTHEMUL N/AFlocculation/Coagulation — 97982 Styrene/Butadiene 22 ROVENE 4823L −51Coagulation CoagulationAluminum Complex

Although a synergistic effect of ALPLEX with latex on stabilizing shaleswas confirmed by PPT test results, this system is fragile and verysensitive to increasing salt concentration and temperature. It was foundthat in 20% NaCl solution, 3% AIRFLEX728 or 3% GENCAL 7463 wereflocculated in a few minutes by adding 4 lb/bbl (11.4 g/l) ALPLEX.Prehydration of ALPLEX in fresh water or addition of some surfactant(e.g. EXP-152) did improve the stability of this system at lowtemperatures, but the latex particle size was still greatly influencedby ALPLEX. Those particles greater than 100 microns in the fluidcontaining ALPLEX may have partially resulted from insoluble lignite (acomponent of ALPLEX). A similar effect was also observed with GENCAL7463. Poor solubility and slow dissolution rate of the lignite in highsalt concentrations is probably the main factor contributing todecreased latex stability.

In order to find a polymer resin that was compatible with a latex systemadditional tests were performed. FIG. 3 shows the effects of differentpolymer resins on the particle size distributions of EXP-155. Among thetested samples, EXP-153 exhibited the best compatibility with this latexsystem.

A new aluminum complex product, EXP-154 (a blend of 45% NaAlO₂, 45%EXP-153 and 10% sodium D-gluconate) was invented for the latex system.FIG. 4 compares the effects on the mud properties for EXP-154 withALPLEX in 12 lb/gal (1.44 kg/l) 20% NaCl/NEW-DRILL/EXP-155 fluids. Theexperimental aluminum complex exhibits improved compatibility with latexand biopolymers. Additionally, EXP-154 is found to control filtration,both API and HTHP, better than does ALPLEX.

Pore Pressure Transmission Testing

Borehole stability effects of the experimental latex system wereevaluated with the pore pressure transmission (PPT) tester previouslydescribed. A preserved Pierre II shale plug, 1 inch diameter by 0.9 inchlong (2.54 cm×2.29 cm long), is placed between two pistons, as describedpreviously in Example 2. The circumference of the shale and pistonssealed with a rubber sleeve. The plug is oriented with the beddingplanes in the parallel or high permeability direction. Drilling fluid at300 psi (2,070 kPa) is displaced through the upstream piston (boreholeside) and seawater at 50 psi (345 kPa) is displaced through thedownstream piston (formation side). The seawater in the downstreampiston is contained with a valve. As mud filtrate enters the boreholeend of the plug, connate water in the shale is displaced into theformation piston. This additional water compresses the water inside thepiston causing the pressure to rise. The pressure increase in theformation piston water is measured as formation pressure (FP) rise.

The EXP-154/EXP-155 fluid produces the best PPT results to date as shownin FIG. 5. The top curve is a standard salt/polymer. The next one downis ALPLEX, the next curve is an EXP-154/AIRFLEX 728 formulation, belowthat is the EXP-154/EXP-155 formulation, and finally at the bottom is a80/20 ISOTEQ fluid, 25% CaCl₂, 6 ppb (17.2 g/l) CARBO-GEL, and 10 ppb(28.6 g/l) OMNI-MUL. Without necessarily being limited to oneexplanation, the superior performance of the EXP-154/EXP-155 fluid isbelieved to be due, at least in part, to its small particle size. Asdiscussed previously, GENCAL 7463 was more efficiently dispersed by theEXP-152 resulting in a much greater percentage of particles smaller thanone micron.

A synergistic effect between latex and aluminum complex has also beenobserved in these tests. Such results may be related to theco-precipitation behavior of EXP-155 and EXP-154. It was found thatEXP-154 becomes insoluble at pH <10. At this condition, EXP-155 alonedoes not precipitate. However, when EXP-154 exists in this system,EXP-155 will be co-precipitated with EXP-154. Because of theirco-precipitation behavior, deposited particles on the shale surface arecomprised of lipophilic and hydrophilic components. This multiphasesystem is capable of creating a semi-permeable membrane, resulting in agreat improvement in osmotic efficiency. Another characteristic ofEXP-155 is that its ultra-fine particles are elastomer-like over a widerange of temperatures. When subjected to differential hydraulicpressure, these ultra-fine particles do not shear or break, but deformand penetrate the hairline fractures and to form an impermeable seal. Atthe temperatures between T_(g) (glass transition temperature) and T_(m)(melting point), most polymers will exhibit rubber-like elasticity. Theglass transition temperature of EXP-155 is 52° F. (11° C.). From therelationship between T_(g) and T_(m) plotted by Boyer, 1963, reproducedin Billmeyer, Textbook of Polymer Science, Second Edition,Wiley-Interscience, New York, 1971, p. 230, we can estimate that T_(m)of EXP-155 is about 300° F. (422° K.). This temperature range coversmost applications in drilling fluids.

Circulation of the fluid was found to be an important element of thelatex plugging mechanism. This was explored in the tests with EXP-155.As the formulation was only 1.5% latex particles by volume (EXP-155 is50% active), insufficient latex was available in the mud to produceplugging under static conditions. With circulation, however, the latexaccumulated on the surface and formed a plugging film. Standardprocedure is to circulate the mud about 7 hours followed by staticexposure overnight. Four or five hours without circulation elapsesbefore the test is started in the morning. This static period eliminatespressure drift due to temperature effects by allowing temperaturevariation from circulation to equilibrium.

When the test started the formation pressure fell from 50 psi (345 kPa)to zero, increasing the differential pressure from 250 to 300 psi (1,720to 2,070 kPa), as seen in FIG. 6. In about 30 hours, the plug began toleak and the formation pressure rose. However, additional circulationsealed the leak in an hour and the pressure again fell to zero. Inprevious tests the circulation was stopped after an hour, and the plugstarted leaking again after another 30 hours. In this test, circulationwas restarted after the pressure rose to 60 psi (414 kPa) in 70 hours(FIG. 6). However, circulation was maintained 5 hours instead of one asbefore. With a few hours of continued circulation after the greaterpressure differential was established, the seal was more stable. Thepressure rose only a few psi in 45 hours.

Photomicrographs of the plug face showed latex accumulation alongmicrofractures in the shale. As the volume and velocity of filtrationflow into these cracks is very small, filtration alone cannot accountfor the latex accumulation at the crack throat. Inside these cracks theclay surface area to filtrate volume ratio is very large resulting inheavy EXP-154 precipitation. The reason may relate to theco-precipitation behavior of EXP-154 and EXP-155 as discussed previous,without being limited to any particular explanation. The precipitationof aluminum complex at pH<19 apparently enhances latex accumulation atthe crack throat. When sufficient latex is deposited to bridge the crackopening, the fracture is sealed and differential pressure is establishedacross the latex. The differential pressure consolidates the latexdeposit into a solid seal. Increasing the differential pressureapparently causes this seal to deform over time (about 30 hours in thecase of the FIG. 6 results) and/or grows additional cracks in the shaleand the shale begins to leak, although the inventors do not necessarilywant to be limited by this explanation. However, additional circulationrapidly sealed the leaks and reestablished the seal. Circulating afterthe full differential pressure was reached formed a stable seal withonly a small pressure rise.

Effect of Latex in Mud Properties

The previous results and discussions deal with latex stability indrilling fluids and its synergy with aluminum complex in improving mudinhabitability to shale formations. Besides, improved performanceparameters achieved by the latex products were also recognized. Twolatex samples, Latex A (8:1 blended AIRFLEX 728 and EXP-152) and EXP-155(8:1 blended GENCAL 7463 and EXP-152), were evaluated in 9.6 lb/gal(1.15 kg/l) 20% NaCl and 12 lb/gal (1.44 kg/) 20% NaCl fluids. Theeffects of adding 3% by volume of these latex products are illustratedin FIGS. 7 and 8. Without obvious effect on the fluid rheology, HTHPfluid loss at 250° F. (121° C.) decreased as much as 45% and 52% in 9.6lb/gal (1.15 kg/l) mud and 35% and 40% in 12 lb/gal (1.44 kg/l) mud byLatex A and EXP-155, respectively. Again, EXP-155 presents betterresults that AIRFLEX 728. Additional tests with EXP-155 are listed inTable II.

TABLE II Typical Performance Parameters of 12 lb/gal 20% NaCl/EXP-155Fluids Formulation Example # 23 24 Water, bbl (I) 0.89 0.89 (141)XAN-PLEX D, lb/bbl (g/l) 0.5 (1.43 g/l) 0.5 (1.43 g/l) BIO-PAQ, lb/bbl(g/l) 4 (11.4) — BIO-LOSE, lb/bbl (g/l) — 4 (11.4) NEW DRILL PLUS,lb/bbl (g/l) 1 (2.86) 1 (2.86) EXP-154, lb/bbl (g/l) 5 5 (14.3) NaCl,lb/bbl (g/l) 77.5 (222) 77.5 (222) EXP-155, % by vol. 3 3 MIL-BAR,lb/unweighted bbl 150 (429) 150 (429) (g/l) Rev-Dust, lb/bbl (g/l) 27(77.2) 27 (77.2) Initial Properties PV, cP 22 21 YP, lb/100 ft² 26 (179)20 (138) 10 sec. gel, lb/100 ft² (kPa) 5 (34) 4 (28) 10 min. gel, lb/100ft² (kPa) 10 (69) 8 (56) API, cm³/30 min 2.5 1.4 pH 10.6 10.7 Density,lb/gal 12.2 12.2 after HR 16 hr @ 150° F. 250° F. — 150° F. 250° F. —(66° C.) (121° C.) (66° C.) (121° C.) after static aged 16 hr @ — — 300°F. — — 300° F. (149° C.) (149° C.) PV, cP 20 21 22 26 24 23 YP, lb/100ft² (kPa) 24 (165) 29 (200) 34 (234) 17 (117) 21 (145) 22 (152) 10 sec.gel, lb/100 ft² (kPa)  6 (41)  7 (48) 10 (69)  4 (28)  5 (34)  5 (34) 10min. gel, lb/100 ft² (kPa)  9 (62) 10 (69) 13 (90)  7 (48)  7 (48)  7(48) API, ml  2.8  3.7  2.8  2.2  2.6  1.8 pH 10.4  9.7  9.7 10.5  9.710.1 HTHP fluid loss, cm³/30 min.  9.4 16.4 12  8.4 13 10.8Toxicity Test

The 96 hour range-finder bioassay results of AIRFLEX 728, GENCAL 7463,EXP-152, EXP-154 and EXP-155 in 12 lb/gal (1.44 kg/l) 20% NaCl/NEW-DRILLfluids are presented in FIG. 9. All products meet the requirement forfluid disposal in the Gulf of Mexico (30,000 ppm) and become less toxicafter solids contamination.

EXAMPLE 7

Because latex polymers contain deformable colloidal particles, it canprovide an excellent bridging and sealing ability to reduce thepermeability of the formation where the lost circulation of drillingfluids may encountered. Table III shows a typical formulation fortesting the sealing ability of latex polymers on permeable formation.Without latex polymer, the fluid loss of this mud is out of control.However, an addition of 3% of a vinyl acetate/ethylene/vinyl chloridelatex polymer, available under the trade designation Airflex 728, intothis mud results in the fluid loss decreasing sharply with time as shownin FIG. 10. Tables IV-VI display the data for FIG. 10.

FIG. 11 shows the section picture of a broken 50 milliDarcy (mD) diskafter testing for four hours at 300° F. with the fluid containing 3%latex polymer. DFE-245 is an admixture of GenCal 7463 and MirataineBET-O30 at a volume ratio of about 9:1. It can be clearly observed thatthe internal filter cake was formed inside of the 50 mD disk.

TABLE III Mud Formulation for Testing Latex effect on High PressureFluid Loss Formulation # 1094-52-1 Water, bbl 0.89 NEW-DRILL ® PLUS,lb/bbl 0.4 MIL-PAC LV, lb/bbl 2 MAX-PLEX, lb/bbl 4 NaCl, lb/bbl 77.5Airflex 728 (latex polymer), % by vol. 3 Maritaine BET-O30, lb/bbl 1

TABLE IV High Temperature High Pressure Fluid loss at 500 psi and 75° F.on 50 mD disk for the mud containing 3% Airflex 728 Time interval, HPHTFL, Average rate of HPHT minutes ml FL, ml/minutes 0-1 4.5 4.50  1-10 20.22 10-30 1.5 0.08 30-60 1.5 0.05  60-120 2.5 0.04

TABLE V High Temperature High Pressure Fluid loss at 500 psi and 250° F.on 50 mD disk for the mud containing 3% Airflex 728 Time interval, HPHTFL, Average rate of HPHT minutes ml FL, ml/minutes 0-1 6 6.00  1-10 40.44 10-30 6 0.30 30-60 4 0.13  60-120 4 0.07

TABLE VI High Temperature High Pressure Fluid loss at 500 psi and 300°F. on 50 mD disk for the mud containing 3% Airflex 728 Time interval,HPHT FL, Average rate of HPHT minutes ml FL, ml/minutes 0-1 10 10  1-1013 1.44 10-30 8 0.4 30-60 6 0.20  60-120 10 0.17 120-180 5 0.08

In the foregoing specification, the invention has been described withreference to specific embodiments thereof, and has been demonstrated aseffective in providing a water-based drilling fluid that can effectivelyreduce the rate of drilling fluid pressure invasion of the boreholewall. However, it will be evident that various modifications and changescan be made thereto without departing from the broader spirit or scopeof the invention as set forth in the appended claims. Accordingly, thespecification is to be regarded in an illustrative rather than arestrictive sense. For example, specific combinations of brines andlatexes and with precipitating agents and/or wetting surfactants orsalts falling within the claimed parameters, but not specificallyidentified or tried in a particular composition to reduce mud pressurepenetration into shale, sand, and other formations, are anticipated tobe within the scope of this invention.

GLOSSARY 4025-70 Low molecular weight amphoteric polymer sold by Amoco,found to be ineffective (also abbreviated as 4025). AIRFLEX 728 Apolyvinylacetate latex (more specifically, an ethylenevinyl chloridevinylacetate copolymer) dispersion sold by Air Products. AIRFLEX 426Vinyl acetate/ethylene copolymer available from Air Products. AIRFLEX7200 Vinyl acetate/ethylene copolymer available from Air Products.ALPLEX ® Proprietary aluminum complex product available from BakerHughes INTEQ. AqS Abbreviation for AQUACOL-S, a glycol available fromBaker Hughes INTEQ. BIO-LOSE Derivatized starch available from BakerHughes INTEQ. BIOPAQ Derivatized starch fluid loss additive availablefrom Baker Hughes INTEQ. CARBO-GEL An amine-treated clay marketed byBaker Hughes INTEQ. CARBO-MUL Invert emulsion emulsifier marketed byBaker Hughes INTEQ. ELVACE 40722-00 Vinylacetate/ethylene copolymerlatex available from Reichhold. EXP-152 Oleamidopropyl betainesurfactant. EXP-153 Sulfonated polymer resin (or sulfonated humic acidwith resin) available from Baker Hughes INTEQ. EXP-154 A mixture of 45%NaAlO₂, 45% EXP-153 and 10% sodium D- gluconate. EXP-155 An 8:1 volumeblend of GENCAL 7463 and EXP-152. FLOWZAN Biopolymer available fromDrilling Specialties. FT-1 A SULFATROL, 90% water-soluble sulfatedasphalt dispersion sold by Baker Hughes INTEQ. GENCAL 7463 Carboxylatedstyrene/butadiene available from Omnova Solution Inc. GENCAL 7470Carboxylated styrene/butadiene available from Omnova Solution Inc.GENFLO 576 Available from Omnova Solution Inc. LD8 A commercial defoameravailable from Baker Hughes INTEQ. LIGCO Lignite sold by Baker HughesINTEQ. MIL-BAR Barite weighting agent available from Baker Hughes INTEQ.MIL-CARB Calcium carbonate weighting agent available from Baker HughesINTEQ. MILPAC LV Low viscosity polyanionic cellulose available fromBaker Hughes INTEQ (sometimes abbreviated as PacLV). MAX-PLEX Analuminum complex for shale stability available from Baker Hughes INTEQ.MIRATAINE BET-O-30 Betaine surfactant from Rhodia NEWDRILL PLUSPartially hydrolyzed polyacrylamide available from Baker Hughes INTEQ.ROVENE 4823L Styrene/butadiene copolymer available from Mallard Creek.ROVENE 6140 Carboxylated styrene/butadiene available from Mallard Creek.ROVENE 9410 Carboxylated styrene/butadiene available from Mallard Creek.SA Abbreviation for sodium aluminate. SYNTHEMUL 97982 Carboxylatedacrylic copolymer available from Reichhold. SYNTHEMUL CPS 401Carboxylated acrylic copolymer available from Reichhold. TYCHEM 68710Carboxylated styrene/butadiene copolymer available from Reichhold. TYLAC68219 Carboxylated styrene/butadiene copolymer available from Reichhold.TYLAC CPS 812 Carboxylated styrene/butadiene copolymer available fromReichhold. VINAC XX-211 Vinyl acetate/ethylene copolymer available AirProducts. XAN-PLEX D Biopolymer available from Baker Hughes INTEQ.

1. A method of inhibiting borehole wall invasion when drilling with awater-based drilling fluid in a subterranean formation, the methodcomprising: a) providing a water-based drilling fluid comprising: i) apolymer latex capable of providing a deformable latex seal on at least aportion of a subterranean formation where the polymer latex is selectedfrom the group consisting of sulfonated styrene/butadiene copolymer,polyvinyl acetate/vinyl chloride/ethylene copolymer, polyvinylacetate/ethylene copolymer, polydimethylsiloxane, and mixtures thereof,where the polymer latex comprises particles that average less than 1micron in size; and ii) water; and b) circulating the water-baseddrilling fluid in contact with a borehole wall.
 2. The method of claim 1where in providing the water-based drilling fluid, the water comprisessalt.
 3. The method of claim 1 where in providing the water-baseddrilling fluid, the fluid further comprises a precipitating agentselected from the group consisting of silicates, aluminum complexes, andmixtures thereof.
 4. The method of claim 1 where in providing thewater-based drilling fluid, the fluid further comprises a surfactant. 5.A method of inhibiting borehole wall invasion when drilling with awater-based drilling fluid in a subterranean formation, the methodcomprising: a) providing a water-based drilling fluid comprising: i) apolymer latex selected from the group consisting of sulfonatedstyrene/butadiene copolymer, polyvinyl acetate/vinyl chloride/ethylenecopolymer, polyvinyl acetate/ethylene copolymer, polydimethylsiloxane,and mixtures thereof; ii) a precipitating agent selected from the groupconsisting of silicates, aluminum complexes, and mixtures thereof; andiii) water; and b) circulating the water-based drilling fluid in contactwith a borehole wall.
 6. The method of claim 5 where in providing thewater-based drilling fluid, the water comprises salt and is a saturatedsalt brine.
 7. The method of claim 5 where in providing the water-baseddrilling fluid, the water-based drilling fluid further comprises asurfactant.
 8. A method of inhibiting borehole wall invasion whendrilling with a water-based drilling fluid in a subterranean formation,the method comprising: a) providing a water-based drilling fluidcomprising: i) a polymer latex selected from the group consisting ofsulfonated styrene/butadiene copolymer, polyvinyl acetate/vinylchloride/ethylene copolymer, polyvinyl acetate/ethylene copolymer,polydimethylsiloxane, and mixtures thereof; ii) a precipitating agentselected from the group consisting of silicates, aluminum complexes, andmixtures thereof; iii) a surfactant; and iv) water; and b) circulatingthe water-based drilling fluid in contact with a borehole wall.
 9. Themethod of claim 8 where in providing the water-based drilling fluid, thewater comprises salt.
 10. The method of claim 9, where the salt isselected from the group consisting of calcium chloride, sodium chloride,potassium chloride, magnesium chloride, calcium bromide, sodium bromide,potassium bromide, calcium nitrate, sodium formate, potassium formate,cesium formate, and mixtures thereof.
 11. The method of claim 8 where inproviding the water-based drilling fluid, the surfactant is selectedfrom the group consisting of betaines, alkali metal alkylene acetates,sultaines, ether carboxylates, and mixtures thereof.
 12. The method ofclaim 8 where in providing the water-based drilling fluid, the polymerlatex is present in the drilling fluid in an amount of from about 0.1 toabout 10 vol. % based on the total water-based drilling fluid.
 13. Themethod of claim 8 where in providing the water-based drilling fluid, theprecipitating agent is present in the drilling fluid in an amount offrom about 0.25 to about 20 lb/bbl based on the total water-baseddrilling fluid.
 14. The method of claim 8 where in providing thewater-based drilling fluid, the surfactant is present in the drillingfluid in an amount of from about 0.005 to about 2 vol. % based on thetotal water-based drilling fluid.
 15. The method of claim 9 where thesalt is present in the drilling fluid in an amount of from about 1 wt. %to about saturation based on the total water-based drilling fluid. 16.The method of claim 8 where in providing the water-based drilling fluid,the polymer latex comprises particles that average less than 1 micron insize.
 17. A method of inhibiting borehole wall invasion when drillingwith a water-based drilling fluid in a subterranean formation, themethod comprising: a) providing a water-based drilling fluid comprising:i) from about 0.1 to about 10 vol. % of a polymer latex selected fromthe group consisting of polymethyl methacrylate, sulfonatedstyrene/butadiene copolymer, polyvinylacetate copolymer, polyvinylacetate/vinyl chloride/ethylene copolymer, polyvinyl acetate/ethylenecopolymer, natural latex, polyisoprene, polydimethylsiloxane, andmixtures thereof; ii) from about 0.25 to about 20 lb/bbl of aprecipitating agent selected from the group consisting of silicates,aluminum complexes, ether carboxylates, and mixtures thereof; iii) atleast 1 wt. % of a salt selected from the group consisting of calciumchloride, sodium chloride, potassium chloride, magnesium chloride,calcium bromide, sodium bromide, potassium bromide, calcium nitrate,sodium formate, potassium formate, cesium formate, and mixtures thereof;iv) from about 0.005 to about 2 vol. % of a surfactant selected from thegroup consisting of betaines, alkali metal alkylene acetates, sultaines,ether carboxylates, and mixtures thereof; and v) water making up thebalance, where the proportions are based on the total water-baseddrilling fluid; and b) circulating the water-based drilling fluid incontact with a borehole wall.
 18. A method of inhibiting borehole wallinvasion when drilling with a water-based drilling fluid in asubterranean formation, the method comprising: a) providing awater-based drilling fluid comprising: i) from about 0.1 to about 10vol. % of a sulfonated styrene/butadiene copolymer latex comprisingparticles that average less than 1 micron in size; ii) from about 0.25to about 20 lb/bbl of a precipitating agent selected from the groupconsisting of silicates, aluminum complexes, ether carboxylates, andmixtures thereof; and iii) water making up the balance, where theproportions are based on the total water-based drilling fluid; and b)circulating the water-based drilling fluid in contact with a boreholewall.
 19. The method of claim 18 where the borehole wall comprisesdepleted sands and shale, and where the drilling fluid stabilizes theshale and reduces drilling fluid loss.
 20. A method of inhibitingborehole wall invasion when drilling with a water-based drilling fluidin a subterranean formation to reduce drilling fluid loss while drillingin depleted sands, the method comprising: a) providing a water-baseddrilling fluid comprising: i) from about 0.1 to about 10 vol. % of asulfonated styrene/butadiene copolymer latex; and ii) water making upthe balance, where the proportions are based on the total water-baseddrilling fluid; and b) circulating the water-based drilling fluid incontact with a borehole wall.